In preparing a well, such as those bored to produce hydrocarbons, for increased production a process of hydraulic fracturing is often used. For example, hydraulic fracturing may be used to extend the effective radius of a wellbore and, thereby, provide increased surface areas, such as to expose more surface area of a hydrocarbon bearing formation and facilitate an increase in the flow of hydrocarbons from the well.
Hydraulic fracturing involves pumping fluids into a well with enough injection rate and pressure to create a fracture in subterranean formations. For example, a casing disposed in a wellbore may be perforated at a depth or depths corresponding to hydrocarbon producing formations. Thereafter, fracturing fluids, such as viscous and/or non-viscous fluids with or without proppants suspended therein, may be injected down the wellbore casing at sufficient volume and pressure to interface with the hydrocarbon producing formations, via the aforementioned perforations, and cause stress fracturing thereof. The aforementioned proppants may be relied upon to remain within the resulting fractures to prevent their closing upon removal of pressure and the fracturing fluid.
Viscosifiers are often used in hydraulic fracturing in order to keep proppants suspended in the fluid for better and more uniform delivery of the proppants into fractures. Such viscosifiers may comprise polymers, such as guar, hydroxypropylguar (HPG), carboxymethylhydroxypropylguar (CMHPG), hydroxyethylcellulose (HEC), carboxymethylhydroxyethylcellulose (CMHEC), carboxymethylcellulose (CMC), and the like, to produce a linear gel. Such linear gels may be produced having such concentrations as 20 to 60 pounds of polymer per 1000 gallons of base fluid, e.g., water.
Although providing increased viscosity as compared to non-viscosified base fluids, in many cases linear gels have insufficient viscosity to adequately transport proppants. Such linear gels may require addition of a significant amount of such polymers to appreciably increase the resulting viscosity. Accordingly, cross-linking is often used to increase viscosity. Cross-linked gelled fluids may be produced by adding cross-linking agents, such as compounds of borate, titanium, zirconium, antimony, aluminum, and the like. Such cross-linked fluids achieve high viscosity at relatively low polymer loadings.
As previously mentioned, viscosifiers are utilized in order to transport proppants, such as sand, resin-coated sand, and ceramics, into a fracture created by the hydraulic pressure. For example, a viscous hydraulic fracturing fluid is utilized not only to carry the proppants to the fracture, but distribute the proppant material throughout the fracture from the casing perforations to the end of the fracture. In the process of fracturing a subterranean formation the proppant laden fluids are passed over porous, permeable media, e.g., the hydrocarbon bearing sands or hydrocarbon bearing carbonates. As the proppant laden fluid flows over this media, the base fluid, e.g., water, is filtered out leaving the dehydrated viscosifier to plate out on the fracture faces, e.g., on the surface of the hydrocarbon bearing sands, resulting in a polymer filter cake.
The aforementioned polymer filter cake is generally very tough and often is substantially impermeable to fluids. The formation of polymer filter cake is a serious problem in the production of hydrocarbons from a well suffering from such damage as the gel residue plugs up porous hydrocarbon producing media reducing or preventing the flow of the desired hydrocarbons.
Polymer filter cake results from the use of both liner gels as well as cross-linked gels. However, although providing improved viscosity, and therefore often providing better distribution of proppants, polymer filter cake residue resulting from cross-linked gels is often less fluid permeable and typically more difficult to remove.
Agents, called breakers (polymer-degrading agents), have been developed to degrade the viscosified fluids to permit them to flow out of the well after the hydraulic fracture treatment is pumped. However, it is very difficult to break or degrade the polymer filter cake because it is difficult to get breakers to the polymer filter cake material in sufficient quantities to cause the polymer filter cake to be degraded or removed. For example, it is very difficult to get good communication between breaker pumped into the well during the fracturing process and the polymer filter cake as the breaker spends itself on the fracturing fluid gel, leaving very little breaker to react with the polymer filter cake.
It would seem that a solution would be to add more breaker. However, the amount of breaker that may be utilized is limited because if too much breaker is added to the fracturing fluids a premature degradation of viscosity will occur and the treatment will be damaged. Although total breaker loading may be increased via use of encapsulated breaker which delays the release of the breaker, the effectiveness of such material on degrading polymer filter cake is poor due to: (1) After release, the breaker will spend itself on unbroken fracture fluid; and (2) After the stimulation is pumped, the dynamics within the created fracture are such that the breaker is in a stagnant situation such that the amount of area that it can contact after release is very small. For example, if the loading of an encapsulated breaker is on the order of 1.0 to 3.0 pounds per thousand gallons of fracturing fluid (as may be provided by a typical loading), the amount of breaker material deposited in the polymer filter cake is quite sparse. Therefore, the effectiveness of the breaker after release is dependent on the movement of fluids by the breaker. This would indicate that if the breaker is carried off by moving fluids returning to the aforementioned perforations, very little of the breaker would remain to contact and degrade the polymer filter cake.
Moreover, current art does not consider that the various breaker materials have appreciable useful half-lives. Halliburton Energy Services, the largest oil field service company in the world, published SPE paper 37228 in 1997, the disclosure of which is hereby incorporated herein by reference, documenting the use of oxidizing breakers and discussing half-life stabilities of these breakers. The paper, in FIG. 3 thereof, shows that for sodium persulfate (one of the most common breakers used in the industry) at temperatures above 200 degrees, the half-life is less than 10 minutes. Current art today is to conduct breaker tests in a lab, measuring the degree of degradation of viscosity with time at a given temperature. The temperature most often is set to be the same as actual down-hole conditions. A problem with this technique, especially concerning polymer filter cake removal, is that the tests are conducted under perfect conditions. When it is considered that flow back of the well after fracture stimulation takes days or even weeks, it becomes clear that the amount of active breaker left to react with filter cake or even any remaining unbroken gelled fluid would be expected to be very small.
It is believed that other attempts to remove polymer filter cake in a somewhat similar fashion consisted of pumping relatively small amounts of breaker ahead of the main treatment via a linear gel fluid pre-pad. However, in such a technique, it is believed by the inventors of the present invention that the breaker was very ineffective due to: (1) The limited amount of breaker; (2) The breaker will spend itself on the linear gel; and (3) There is not enough breaker left to compensate for half-life degradation to degrade or remove any polymer filter cake that is formed during the main treatment.
Attempts at working around the use of polymer gels for delivery of proppants, and thus to reduce damage associated with polymer filter cakes, have included pumping massive amounts of proppants into a well using a non-viscosified or relatively slightly viscosified fluid. However, these techniques have generally not been successful as it is typically not possible to force a well to accept massive amounts of proppants, in addition to the results being highly unpredictable with respect to the delivery of the proppants into the created fracture.
Accordingly, as problematic as the formation of polymer filter cake is, the use of viscosified fracture treatments are typically desirable in order to provide lateral distribution of the proppant. However, the result of the use of polymer gel fluids to deliver the proppants is that in many cases only a third or less of the fracture created can actually contribute to production.
Accordingly, a need exists in the art for systems and methods to minimize damage resulting from polymer filter cake to fracture faces. A further need exists in the art for systems and methods adapted to provide improved removal of polymer filter cakes. A still further need exists in the art for systems and methods to provide improved communication between polymer filter cake and breaker agents to facilitate improved removal of polymer filter cakes.